Recovery of Hydrocarbons Using Artificial Topseals

ABSTRACT

A method is described for recovering viscous oil such as bitumen from a subsurface formation. The method involves creating an artificial barrier in a subterranean zone above or proximate a top of the subsurface formation. The barrier is largely impermeable to fluid flow. The method also includes reducing the viscosity of the viscous oil and mobilizing hydrocarbons into a readily flowable heavy oil by addition of heat and/or solvent. Heating preferably uses a plurality of heat injection wells. The method further includes producing the heavy oil using a production method that preserves the integrity of the artificial barrier.

CROSS-REFERENCE TO RELATED APPLICATION

The present application claims priority to and the benefit of U.S.Provisional Patent Application Ser. No. 61/299,696, which was filed on29 Jan. 2010, which was entitled, RECOVERY OF HYDROCARBONS USINGARTIFICIAL TOPSEALS, and which is incorporated herein by reference inits entirety for all purposes.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to the field of hydrocarbon recovery fromsubsurface formations. More specifically, the present invention relatesto the in situ recovery of hydrocarbon fluids from viscous oilformations including, for example, oil sands formations containingbitumen. The present invention also relates to methods for sealing aformation to prevent the upward migration of an injected heating vaporand/or solvent.

2. Discussion of Technology

This section is intended to introduce various aspects of the art, whichmay be associated with exemplary embodiments of the present disclosure.This discussion is believed to assist in providing a framework tofacilitate a better understanding of particular aspects of the presentdisclosure. Accordingly, it should be understood that this sectionshould be read in this light, and not necessarily as admissions of priorart.

For many years, oil companies have explored for and producedhydrocarbons. While the term “hydrocarbons” generally refers to anyorganic material with molecular structures containing carbon bonded tohydrogen, hydrocarbons have primarily been produced from subsurfaceformations where the hydrocarbon is in a fluid form. In a liquid state,such hydrocarbons are commonly referred to as “oil,” while in a gasstate such hydrocarbons are known as “natural gas.”

In the last 25 years, energy companies have investigated the productionof hydrocarbons that reside in a highly viscous or even solid(non-fluid) form. Such hydrocarbons may generally be referred to as“heavy hydrocarbons” and “solid hydrocarbons,” respectively.

“Solid hydrocarbons” refers to any hydrocarbon material that is foundnaturally in substantially solid form at formation conditions. Examplesinclude kerogen, coal, shungites, asphaltites, and natural mineralwaxes. Heavy hydrocarbons include hydrocarbons that are highly viscousat ambient conditions (15°-25° C. and 1 atm pressure). These includebitumen, asphalt, and so-called heavy oil.

The viscosity of heavy hydrocarbons is generally greater than about 100centipoise at 15° C. Bitumen and heavy oil are sometimes togetherreferred to as viscous oils. Heavy hydrocarbons may also be classifiedby API gravity, and generally have an API gravity below about 20degrees. Heavy oil, for example, generally has an API gravity of about10 to 20 degrees, whereas tar generally has an API gravity below about10 degrees.

The terms “bitumen” and “tar” are sometimes used interchangeably. Bothmaterials are highly viscous, black, and sticky substances. However, thenaturally occurring tar in subsurface formations is technically bitumen.Bitumen is a non-crystalline, highly viscous hydrocarbon material thatis substantially soluble in carbon disulfide. Bitumen includes highlycondensed polycyclic aromatic hydrocarbons, and is commonly used forpaving roads.

Viscous oil deposits are located in various regions of the world. Forexample, viscous oils have been found in abundance in the Milne PointField on the North Slope of Alaska. Viscous hydrocarbons also exist inthe Jobo region of Venezuela, and have been found in the Edna andSisquoc regions in California. In addition, extensive formations of oilsands exist in northern Alberta, Canada. These formations are sometimesreferred to as “tar sands,” though they technically contain bitumen.

The Athabasca oil sands deposit in northern Alberta is one of thelargest viscous oil deposits in the world. There are also sizable oilsands deposits on Melville Island in the Canadian Arctic, and twosmaller deposits in northern Alberta near Cold Lake and Peace River. Theoil sands contain substantial amounts of bitumen.

There are two methods currently used to extract bitumen from the ground.These are an open pit mining process, and an in situ recovery process.In either instance, once extracted, oil sands producers typicallymaintain the hydrocarbon material in a heated condition and/or addlighter hydrocarbons to the bitumen to allow it to flow throughpipelines. Upgraders then process the bitumen into synthetic crude.

Open pit mining resembles conventional mining techniques, and iseffective in extracting oil sands deposits if the deposits aresufficiently tar-like. Mining of bitumen deposits is a well-establishedtechnology. However, bitumen mining has several drawbacks. First openpit mining is generally limited to oil sands deposits that are near thesurface. Generally, production is limited to formations that are lessthan about 80 meters in depth due to the cost of overburden removal. Inaddition, there are high capital and maintenance costs associated withsolids-handling equipment. Further, open pit mining may require highwater usage for separating the bitumen from the sand. Finally, open pitmining creates a substantial disruption of the surface for years duringrecovery operations and until restoration activities are performed.

The bulk of Canada's oil sands deposits are too deep below the surfaceto use open pit mining. However, the in situ recovery method may reachthe deeper deposits. In situ extraction often involves the use of aheated fluid to separate bitumen from the sands at a selected depth, andpermit the heated bitumen to flow through wells to the surface. Theheated fluid may be steam. Alternatively, the heated fluid may be asolvent vapor or a steam-solvent mixture. In some processes, unheatedsolvent is used in a liquid or vapor state.

Several steam injection processes have been suggested for heatingbitumen. One general method for recovering viscous hydrocarbons is byusing a “steam stimulation” technique known as the “huff-and-puff”process. In the huff-and-puff process, steam is injected into aformation by means of one or more wells. The wells are then shut-in topermit the steam to heat the bitumen, thereby reducing its viscosity.Subsequently, all formation fluids, including mobilized bitumen and atleast partially condensed steam, are produced together from the wellusing accumulated reservoir pressure as the driving force forproduction.

Initially in the huff-and-puff process, sufficient pressure may beavailable in the vicinity of the wellbores to lift fluids to thesurface. As the pressure falls, artificial lifting methods are normallyemployed. Production is terminated when artificial lift is no longereffective. Steam is then injected again. This cycle may take place manytimes until oil production is no longer economical.

In the huff-and-puff method, the highest pressures and temperaturesexist in the vicinity of the well immediately following the injectionphase. Normally this pressure and temperature will correspond to theproperties of the steam which was employed. Before oil can be moved fromthe remote parts of the reservoir to the well, the pressure in the nearwell region must fall so that it is lower than the distant reservoirpressure. During this initial depressuring phase, the near-wellborereservoir material cools down as water flashes into steam. The firstproduction from the well thus tends to be steam, and this tends to befollowed by hot water. Eventually, the pressure is low enough that oilcan move to the wellbore.

In the initial production phase, much of the heat which was put into thereservoir with the steam is simply removed again as steam and hot water.A major inefficiency of the huff and puff process is that this heat mustbe supplied during each cycle. As the available oil becomes more remotefrom the well, this cyclic wasted heat quantity increases, meaning thatmore hot water but less mobilized bitumen is produced.

U.S. Pat. No. 4,344,485, entitled “Method for Continuously ProducingViscous Hydrocarbons by Gravity Drainage While Injecting Heated Fluids,”presented an improved steam injection technique. This technique is knownas steam-assisted gravity drainage, or SAGD. This is a low pressure insitu application.

In SAGD, an injection well is completed for injecting a heated fluidsuch as steam. A production well for producing oil and condensate isalso drilled into the formation adjacent to the injection well. Thewells are also completed such that separate oil and water flowpaths inat least the near-wellbore region of the production well are ensuredwith appropriately throttled injection and production rates. Variants ofSAGD exist in which solvent is added to the steam (see U.S. Pat. No.6,662,872) or solvent completely replaces the steam (see U.S. Pat. No.5,407,009 and U.S. Pat. No. 6,883,607).

Initially, the formation may be fractured by injecting the heated fluidvia the injection well at a higher-than-fracture pressure.Alternatively, a suitable fracturing fluid may be used to createfractures. Alternatively still, no fracturing is performed and fluidcommunication between the wells is established simply by heating.

Next, steam is injected via the injection well to heat the formation. Asthe steam condenses and gives up its heat to the formation, the viscoushydrocarbons are mobilized. The hydrocarbons then drain by gravitytoward the production well. Mobilized viscous hydrocarbons are able tobe recovered continuously through the production well.

In one embodiment, two nearly horizontal wells are formed, with one wellbeing located directly above the other. In this arrangement, the upperwell is used to inject steam and then remove water and condensate, whilethe lower well is used to continuously produce the mobilized viscousoil. In another embodiment, two vertical wells are provided, with onewell being the steam injection/water production well, and the otherbeing a hydrocarbon production well. In yet a third embodiment, ahorizontal well is drilled and extended below a vertical steam injectionwell. Steam is injected into the formation, causing the mobilization ofheavy oil. Oil is then produced through the elongated horizontal well.

A requirement of SAGD and other in situ bitumen recovery methods is theneed for a largely impermeable topseal. A topseal is an impermeablegeological barrier provided in a more shallow formation. The topsealserves to contain injected fluids and/or gases that are released orcreated during heating and production. These released gases may includegreenhouse gases such as methane or carbon dioxide. Moreover, theinjected fluids contain heat which would reduce process efficiency iflost to an overburden region.

Many shallow bitumen deposits have tops that are geologic unconformitiessuch as eroded zones. Such zones are not effective topseals as they arerelatively permeable to fluid flow. Lack of a topseal typically preventseconomic recovery of mobilized heavy hydrocarbon deposits since anyinjectant (e.g., steam) readily channels into the permeable overburdenand is lost to non-productive areas. In some cases, the injectant willleak all the way to the surface. In either instance, the injectant doesnot effectively penetrate the viscous oil material.

Therefore, there is a need for new methods for recovering viscous oilfrom subterranean deposits lacking effective topseals.

SUMMARY OF THE INVENTION

The methods described herein have various benefits in the conducting ofoil and gas exploration and production activities in formations havingoil sands or other viscous oil deposits.

First, a method is provided for recovering a viscous hydrocarbon from asubsurface formation. In one embodiment, the method includes creating anartificial barrier in a subterranean zone. The subterranean zone isabove or proximate a top of the subsurface formation. Preferably, theartificial barrier is formed within 5 meters of the top of thesubsurface formation. The artificial barrier is largely impermeable tofluid flow.

The artificial barrier may be formed by injecting a polymer solutioninto the subterranean zone. The polymer solution chemically reacts insitu to form a gel. Preferably, the polymer solution is injected intothe subterranean zone at a pressure below the fracture pressure.Alternatively, a fluid may be injected into the subterranean zone abovethe fracture pressure so to form horizontal fractures only and fill thefractures with a barrier-forming substance. The artificial barrier mayalternatively be formed by injecting a waxy emulsion, a clay slurry, ormolten sulfur, or by jetting in a grout material.

In another arrangement, the step of creating an artificial barrier mayinvolve completing a plurality of refrigerator wells in the subterraneanzone. In this instance, a cooling fluid is circulated through each ofthe plurality of refrigerator wells. Circulation of the cooling fluidcauses water in the subterranean zone to covert to ice in situ. Thus, afrozen horizontal barrier is formed.

The method also includes reducing the viscosity of the viscoushydrocarbon, and mobilizing the viscous hydrocarbon into a readilyflowable heavy oil. In a preferred embodiment, this is accomplished byuse of heat applied to the subsurface formation. Heating the formationhas the effect of reducing the viscosity of the viscous hydrocarbon, andmobilizing the viscous hydrocarbon into a readily flowable heavy oil. Inone aspect, heating involves the creation of a plurality ofheat-supplying wells. Each of the heat-supplying wells may carry anelectric current. In this instance, heating the subsurface formationcomprises applying electrical-resistive heat to the subsurface formationto reduce the viscosity of the viscous hydrocarbon. In another aspect,each of the heat-supplying wells is a heat injection well. In thisinstance, heating the subsurface formation comprises injecting a heated,vaporized fluid as an injectant through each of the injection wells. Theinjectant may be, for example, steam, a hydrocarbon solvent, orcombinations thereof. In some embodiments, a hydrocarbon solvent may beinjected in an unheated stated.

The method further includes producing the heavy oil to the surface. Theproduction process uses a low-pressure production method. An example isa gravity drainage method that provides for essentially continuousproduction. The production method is compatible with the artificialbarrier, meaning that the production method does not compromise theintegrity of the topseal.

The viscous hydrocarbon may have a viscosity greater than about 100centipoise in its undisturbed in situ state. In one aspect, the viscoushydrocarbon comprises primarily bitumen.

An alternative method for recovering viscous hydrocarbons from asubsurface formation is provided herein. This method may first compriselocating a permeable subterranean zone geologically above the subsurfaceformation. A gelling fluid is then injected into the subterranean zonein a liquid phase. After a time, the gelling fluid will gel, forming anartificial topseal over the subsurface formation.

In one aspect, the gelling fluid is a polymer solution that undergoes achemical reaction within the subterranean zone to slowly form the gel.In another aspect, the gelling fluid is a temperature-sensitive, waxy,oil-external emulsion comprising oil, added wax, and water. The waxyemulsion is formulated to be substantially a solid at initial in situtemperature conditions and in situ pressures in the subterranean zone.In order to inject the gelling fluid, the method further comprisesheating the waxy, oil-external emulsion into a flowable liquid at asurface heater before injecting the emulsion into the permeablesubterranean zone. The emulsion will form the gel as it cools in thesubterranean zone. In another aspect, the injected fluid chemicallyreacts in situ to form a solid precipitate which leads to pore pluggingand permeability reduction of the formation rock.

The method also includes forming a plurality of heat injection wellsinto the subsurface formation, and also forming a plurality of producerwells into the subsurface formation. Each injector well has one or moreassociated producer wells, thereby creating sets of wells for therecovery operation. In one aspect, each of the heat injection wells iscompleted horizontally within the subsurface formation. In anotheraspect, each of the producer wells is completed horizontally within thesubsurface formation. In one embodiment, each of the heat injectionwells is completed horizontally within the subsurface formation and eachof the producer wells is completed horizontally within the subsurfaceformation, such that each of the sets of wells is a pair of wells, andeach of the pairs of wells is completed substantially within a verticalplane.

The method further includes injecting steam into each of the pluralityof heat injection wells. Injecting steam serves to heat the subsurfaceformation. The heat (i) creates steam chambers within the subsurfaceformation, (ii) reduces the viscosity of the viscous hydrocarbons, and(iii) mobilizes the viscous hydrocarbons into a flowable heavy oil. Inone aspect, the step of injecting steam into each of the plurality ofheat injection wells is ceased before the steam chamber reaches theartificial topseal. A preserved viscous hydrocarbon layer at the top ofthe subsurface formation serves to enhance the effectiveness of theartificial topseal. Alternatively, the composition of steam is modifiedto include a hydrocarbon solvent, with the temperature of the injectantbeing reduced before the steam chamber compromises the effectiveness ofthe topseal.

The method also comprises producing the heavy oil through each of theplurality of producer wells.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the present inventions can be better understood, certainillustrations and flow charts are appended hereto. It is to be noted,however, that the drawings illustrate only selected embodiments of theinventions and are therefore not to be considered limiting of scope, forthe inventions may admit to other equally effective embodiments andapplications.

FIGS. 1A through 1F present cross-sectional views of subsurface stratain an oil field. The strata include a subsurface formation having aviscous oil. A substantially horizontal barrier has been placed as atopseal over the subsurface formation.

In FIG. 1A, heat injection wells and production wells have beencompleted in the subsurface formation. No heating has yet taken place inthe subsurface formation.

In FIG. 1B, steam or other heated vapor is being injected into thesubsurface formation through the heat injection wells. Small but growingsteam chambers are seen around the heat injection wells.

In FIG. 1C, heated vapor continues to be injected into the subsurfaceformation. The steam chambers have enlarged around the heat injectionwells. In addition oil drainage layers have formed where viscous oilflows under low pressure towards the production wells.

In FIG. 1D, heated vapor continues to be injected into the subsurfaceformation. The steam chambers have approached the topseal. The oildrainage layers have reached the top of the subsurface formation.

In FIG. 1E, the steam chambers have merged to form a single steamchamber. The topseal allows viscous oil to be mobilized to the top ofthe subsurface formation while substantially preventing heated vaporfrom migrating into the subterranean zone. Heated solvent is optionallyinjected into the subsurface formation to avoid the encroachment ofhigh-temperature steam into the topseal. This provides for themobilization of additional viscous hydrocarbons without compromising thetopseal.

In FIG. 1F, the steam chambers have expanded away from the heatinjection wells to substantially fill the subsurface formation. An oildrainage layer continues to advance ahead of the heated vapor.

FIGS. 2A and 2B provide cross-sectional views of cooling wells as may beused to freeze native waters, in alternate embodiments.

FIG. 2A shows a cooling well where a cooling fluid is injected down thebore of a working string, passed through a single expander valve, andcirculated back to the surface through an annulus.

FIG. 2B shows a cooling well where a cooling fluid is injected down thebore of a working string, passed through two separate expander valves inthe bore, and circulated back to the surface through the annulus.

FIG. 3 is a flowchart showing steps that may be taken to set a waxyemulsion in a subterranean zone to form an artificial barrier.

FIG. 4 is a cross-sectional view of a pair of wells, representing a heatinjection well and a production well, in one embodiment. The heatinjection well is used to decrease the viscosity of bitumen or otherviscous hydrocarbon in a hydrocarbon formation.

FIG. 5 is a flowchart showing steps for a method of recovering a viscoushydrocarbon from a subsurface formation. The method includes creating anartificial barrier in a subterranean zone above or proximate a top ofthe subsurface formation, and heating the subsurface formation in orderto reduce the viscosity of the viscous hydrocarbon.

FIG. 6 is a flowchart showing steps for a method for recovering viscoushydrocarbons from a subsurface formation, in an alternate embodiment.The method includes injecting a polymer solution into the subterraneanzone in a liquid phase, and allowing time for the polymer solution togel within the subterranean zone and form an artificial topseal over thesubsurface formation.

DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS Definitions

As used herein, the term “hydrocarbon” refers to an organic compoundthat includes primarily, if not exclusively, the elements hydrogen andcarbon. Hydrocarbons may also include other elements, such as, but notlimited to, halogens, metallic elements, nitrogen, oxygen, and/orsulfur. Hydrocarbons generally fall into two classes: aliphatic, orstraight chain hydrocarbons, and cyclic, or closed ring hydrocarbons,including cyclic terpenes. Examples of hydrocarbon-containing materialsinclude any form of natural gas, oil, coal, and bitumen.

As used herein, the term “hydrocarbon fluids” refers to a hydrocarbon ormixtures of hydrocarbons that are gases or liquids. For example,hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbonsthat are gases or liquids at formation conditions, at processingconditions or at ambient conditions (15° C. and 1 atm pressure).Hydrocarbon fluids may include, for example, oil, natural gas, coalbedmethane, shale oil, pyrolysis oil, pyrolysis gas, a pyrolysis product ofcoal, and other hydrocarbons that are in a gaseous or liquid state.

The term “viscous hydrocarbon” refers to a hydrocarbon material residingin a subsurface formation that is in a generally non-flowable condition.Viscous hydrocarbons have a viscosity that is generally greater thanabout 100 centipoise at 15° C. A non-limiting example is bitumen.

As used herein, the term “heavy oil” refers to relatively high viscosityand high density hydrocarbons, such as bitumen. Gas-free heavy oilgenerally has a viscosity of greater than 100 centipoise and a densityof less than 20 degrees API gravity (greater than about 900kilograms/cubic meter). Heavy oil may include carbon and hydrogen, aswell as smaller concentrations of sulfur, oxygen, and nitrogen. Heavyoil may also include aromatics or other complex ring hydrocarbons.

As used herein, the term “subsurface” refers to geologic strataoccurring below the earth's surface.

The terms “zone” or “subterranean zone” refer to a selected portion of aformation. The formation may or may not contain hydrocarbons orformation water.

As used herein, the term “subsurface formation” means any definablesubsurface region. The formation may contain one or morehydrocarbon-containing layers, one or more non-hydrocarbon containinglayers, an overburden, and/or an underburden of any geologic formation.An “overburden” and/or an “underburden” is geological material above orbelow the formation of interest. An overburden or underburden mayinclude one or more different types of substantially impermeablematerials. For example, overburden and/or underburden may include rock,shale, mudstone, or wet/tight carbonate (i.e., an impermeable carbonatewithout hydrocarbons). In some cases, the overburden and/or underburdenmay be permeable.

As used herein, the terms “produced fluids” and “production fluids”refer to liquids and/or gases removed from a subsurface formation,including, for example, an organic-rich rock formation. Produced fluidsmay include both hydrocarbon fluids and non-hydrocarbon fluids.Production fluids may include, but are not limited to, pyrolyzed shaleoil, synthesis gas, a pyrolysis product of coal, carbon dioxide,hydrogen sulfide and water (including steam).

As used herein, the term “fluid” refers to gases, liquids, andcombinations of gases and liquids, as well as to combinations of gasesand solids, and combinations of liquids and solids.

As used herein, the term “gas” refers to a fluid that is in its vaporphase at 1 atm and 15° C.

As used herein, the term “oil” refers to a hydrocarbon fluid containingprimarily a mixture of condensable hydrocarbons.

As used herein, the term “wellbore” refers to a hole in the subsurfacemade by drilling or insertion of a conduit into the subsurface. Awellbore may have a substantially circular cross section, or othercross-sectional shape. As used herein, the term “well”, when referringto an opening in the formation, may be used interchangeably with theterm “wellbore.”

The term “tubular member” refers to any pipe, such as a joint of casing,a portion of a liner, or a pup joint.

As used herein, the term “oil-external emulsion” refers to any emulsionwhere oil is the continuous phase.

The term “wax” refers to any one of various substances that issubstantially hydrophobic, that is, insoluble in water, and that has arelatively low viscosity when melted. The wax may be, for example, apetroleum-derived wax such as a paraffin. The wax may alternatively be anon-petroleum natural wax such as, for example, beeswax or vegetablewax. One non-limiting example of a wax is Imperial Oil Wax 1010. Wax maybe present in oil naturally or may be added, in which case it isreferred to as “added wax.”

The term “emulsifying agent” refers to any substance that assists in theformation and stabilization of emulsions. Non-limiting examples ofemulsifying agents include surfactants (both ionic and non-ionic), finemineral solids (such as fumed silica and bentonite), and any pHmodifying agent (including, but not limited to metal hydroxides).

The term “solvent” refers to any fluid that is significantly solublewith a particular liquid, resulting in a homogeneous mixture at thetemperature and pressure of interest. Solubility amounts of the solventin the liquid resulting in a homogeneous mixture may be greater than 10mass percent. Non-limiting examples of solvents for hydrocarbon oilsinclude propane, heptane, diesel, and kerosene.

The term “gel strength” refers to the shear stress required to cause afluid to initiate flow. An indicator of gel strength is the maximumpressure gradient that may be applied to a fluid before flow occursthrough an area plugged with the gel.

Description of Selected Specific Embodiments

Methods are provided herein for recovering a viscous hydrocarbon from asubsurface formation. The methods are intended to create an extendedartificial topseal near or just above the top of the subsurfaceformation. The topseal may be greater than one acre or, more preferably,greater than about five acres (20,232 m²). Alternatively and morepreferably, the topseal is substantially continuous over an area that isat least about ten acres (40,464 m²).

Once in place, the topseal allows for the recovery of hydrocarbons fromoil sands or so-called “tar sands” without need of surface mining oropen pit mining. In this respect, the subsurface formation may beeffectively heated using an injectant such as steam or a hydrocarbonvapor with minimal to no loss of the heated injectant. The methodsherein may be employed even for viscous oil deposits that couldotherwise be recovered through open pit mining. This preserves thesurface and reduces capital costs.

FIG. 1A presents a cross-sectional view of subsurface strata in an oilfield 100 under development. The oil field 100 targets a subsurfaceformation 110 containing viscous hydrocarbons such as bitumen. Theviscous hydrocarbons are in an unheated and immobiled state. However, itis desired to recover the viscous hydrocarbons from the subsurfaceformation 110 without disrupting the surface 102 of the oil field 100.

In FIG. 1A, it can be seen that the oil field 100 contains near-surfacestrata 104 above the subsurface formation 110. Between the formation 110of interest and the near-surface strata 104 is a subterranean zone 106.Below the formation 110 is an underburden 112.

The underburden 112 is typically largely impermeable to fluid flow.However, the subterranean zone 106 is comprised of sand, or a mixture ofsand and soil, and is highly permeable. The subterranean zone 106 maygeologically be a part of the same formation as near-surface strata 104.In any instance, the highly permeable nature of the subterranean zone106 prevents the effective use of an injectant as part of an in siturecovery process.

In accordance with the methods herein, an artificial barrier may becreated in the subterranean zone 106. An artificial barrier is shown at108 extending across the top of the subsurface formation 110. Theartificial barrier 108 serves as a topseal, and once created is largelyimpermeable to fluid flow. The artificial barrier 108 allows for the useof an injectant for an in situ recovery process within the subsurfaceformation 110. The artificial barrier may be several feet in thicknesson average but may be much thinner, for example less than 1 foot or evenless than about 1 inch (2.54 cm).

In order to place the artificial barrier 108 in the subterranean zone106, various service wells 120 have been formed. In FIG. 1A, the servicewells 120 are shown as completed vertically. However, in some operationsit may be preferred to complete the service wells 120 horizontally alongthe subterranean zone.

Depending on the nature of the artificial barrier 108, the wells mayserve different purposes. In one aspect, the artificial barrier 108 isformed using service wells 120 by injection of an injectable mixturesuch as a polymer solution, which flows through the permeable zone andwhich gels in situ. Alternatively, the injectable mixture may be moltensulfur (see, for example, U.S. Pat. No. 7,631,689), or may be grout suchas sulfur cement, Portland cement, or clay which is injected into theformation 110 as a slurry. In this instance, the molten sulfur, cement,or grout is injected into the subterranean zone 106 under pressure toplug the pores and vugs in the permeable subterranean zone 106. In someembodiments, the injectable mixture is dispersed above the subsurfaceformation 110 through interconnecting horizontal fractures.

The subterranean zone 106 may be shallow, for example less than 300 feetin depth. Because of a shallow nature of the subterranean zone 106, theinjectable mixture may be injected at a pressure that exceeds theformation fracture pressure of the strata 104, 106. In this instance,the fractures will primarily be horizontal in nature. It can be seenfrom FIG. 1A that the injectable mixture has spread substantiallyhorizontally over and across the subsurface formation 110 to create acontinuous topseal.

In another arrangement, the service wells 120 comprise a plurality ofrefrigerator wells. In this instance, a cooling fluid is circulatedthrough each of the plurality of refrigerator wells 120. The coolingfluid may be a chilled liquid, a vaporizing refrigerant, or a partiallyfrozen slurry. In one aspect, the cooling fluid may be a brine,glycol-water solution, or alcohol-water solution. In another aspect, thecooling fluid is comprised at least of 50 mol. percent of propane,propylene, ethane, ethylene, or a mixture thereof In this arrangement,the service wells 120 will preferably have a substantial horizontalportion (not shown in FIG. 1A). The horizontal portion of the variousservice wells 120 will extend through portions of the subterranean zone106.

Circulation of the cooling fluid through the horizontal portions of theservice wells 120 causes native water in the subterranean zone toconvert to ice. This, in turn, creates a substantially horizontal frozenbarrier. The frozen barrier serves as the topseal 108. In relativelycold soils such as those found in the Canadian oil sands of northernAlberta, wells carrying a cooling fluid may be spaced up to about 5meters apart to achieve a frozen layer. According to H.J. Jessberger etal. in Chapter 2.4 of Geotechnical Engineering Handbook (UlrichSmoltczyk ed. 2002, Ernst & Sohn), continuous freezing may occur withinabout a year.

In one arrangement of cooling wells, the wellbores, especially forshallow formations, have so-called “river-crossing borings.” This meansthat the wellbores go down into the subterranean zone 106, run largelyhorizontally, and then bend upwards to return to the surface 102. Thisarrangement simplifies the coolant circulation process. Such anarrangement may be attractive in northern Alberta, considering theshallow depths of the oil sands located there.

The use of the service wells 120 as cooling wells will require fluidcirculating equipment, including fluid pumps and refrigerationequipment. Such equipment is represented schematically at 125 in FIG.1A. Such equipment may be run continuously until the frozen horizontalbarrier is completed, and then run intermittently to maintain theartificial barrier 108 in a frozen state. However, where a horizontalfrozen barrier is employed as the topseal, operating temperatures in thesubsurface formation 110 may need to be kept low so as not to rapidlymelt the topseal. This is so even if the circulation of the coolingfluid is continued after the artificial barrier 108 is constructed. Inone aspect, light non-condensable gases may be injected into the top ofthe subsurface formation 110 to create an insulative later at the top ofthe formation 110. Such light gases preferably include hydrocarbonsolvents in the C₃-C₅ range of components, but may also include inertgases such as nitrogen or helium.

The use of subsurface freezing to provide a barrier to fluid flow isknown in the art. Shell Exploration and Production Company has discussedthe use of freeze walls at the periphery of an oil shale production areain several patents, including U.S. Pat. No. 6,880,633 and U.S. Pat. No.7,032,660. Shell's '660 patent uses subsurface freezing to protectagainst groundwater flow and groundwater contamination during in situshale oil production.

U.S. Pat. No. 4,860,544 describes a method for creating a closed,flow-impervious cryogenic barrier by extending an array of freeze wellsat angles into the earth. This forms an array of inverted, tent-likefrozen structures below the earth surface. Similarly, U.S. Pat. No.3,267,680 describes the formation of freeze walls of increasedmechanical strength by using a series of freeze wells that alternate inangle. Specifically, every other well is vertical while the intermediatewells are 3° to 30° off of vertical. U.S. Pat. No. 3,559,737 describesforming an underground gas storage chamber by sealing caprock fracturesof a permeable formation using cryogenic cooling. Use of a downholethrottle is disclosed as a means of cooling.

Additional patents that disclose the use of so-called freeze wallsinclude U.S. Pat. Nos. 3,528,252; 3,943,722; 3,729,965; 4,358,222; and4,607,488. WO Pat. No. 98996480 is also of interest. Also, K. Stoss andJ. Valk, “Uses and Limitations of Ground Freezing with Liquid Nitrogen”,Engineering Geology, 13, pp. 485-494 (1979); and R. Rupprecht,“Application of the Ground-Freezing Method to Penetrate a Sequence ofWater-Bearing and Dry Formations—Three Construction Cases”, EngineeringGeology, 13, pp. 541-546 (1979) discusses subsurface freezingtechniques. The disclosures of the above-listed “freeze wall” patentsand technical articles are hereby incorporated by reference in theirentireties.

FIG. 2A provides a cross-sectional view of an illustrative cooling well220A where refrigeration occurs downhole. The cooling well 220A is anexample of a service well 120 from FIG. 1A as may be used in theformation of the artificial barrier 108. In FIG. 2A, the well 220A isseen traversing from the earth surface 102, through the near-surfacestrata 104, and into the subterranean zone 106.

The cooling well 220A defines a bore 225 cut through the near-surfacestrata 104 and into the subterranean zone 106 using any known drillingprocedure or technique. The bore 225 of the cooling well 220A is linedwith a string of casing 222. The string of casing 222, in turn, issealed into place using a curable material such as cement 224. Thecement 224 not only supports the casing 222 in the well 220A, but alsoprevents the migration of fluids along the wellbore 225 between thenear-surface strata 104 and the subterranean zone 106. The casing 222and cement 224 preferably are not perforated at any point.

Within the casing 222 is a working string 230. The working string 230may be, for example, a string of tubing, a string of drill pipe, orcoiled tubing. Preferably, the working string 230 is centralized withinthe casing 222 through centralizers or collars (not shown). The workingstring 230 defines a bore 235 that receives a cooling fluid. The workingstring 230 extends from the earth surface 102 to an end 240 of thecooling well 220A.

The cooling well 220A includes an extended horizontal portion 206. Thehorizontal portion 206 runs along the plane of the subterranean zone106. Circulation of the cooling fluid causes water residing in the porespace of the subterranean zone 106 to freeze. The water may be nativewater.

A circulation path for the cooling fluid is seen in FIG. 2A. The coolingfluid is injected into the bore 235 of the working string 230, as seenby arrows “I.” The cooling fluid travels under pressure to the end 240of the cooling well 220A, and then returns to the earth surface 102through an annulus 232 formed between the working string 230 and thesurrounding casing 222. Arrows “A” demonstrate flow of the cooling fluidthrough the annulus 232.

The cooling fluid serves as a working fluid for distributing cold energyto the subterranean zone 106. Upon return to the surface 102, thecooling fluid is captured at a wellhead (not shown). From there, thecooling fluid is rechilled in equipment 125 (seen in FIG. 1A) andrecirculated.

Various types of fluids may be used as a cooling fluid, not all of whichrequire downhole refrigeration. U.S. Pat. No. 3,372,550 discloses theuse of a carbon dioxide slurry as a subsurface cooling fluid. U.S. Pat.No. 3,271,962 describes a method of freezing the earth around a mineshaft using multiple freeze wells connected to a common subterraneancavity. The use of brines or partially frozen brine slurries as coolingfluids is disclosed. Particularly suitable cooling fluids forcirculation through cooling well 220A include a fluid comprised at leastof 50 mol. percent of propane, propylene, ethane, ethylene, or a mixturethereof

In one aspect, the cooling fluid may be chilled prior to injection intothe well 220A. For example, a surface refrigeration system (part ofsurface equipment 125) may be used to chill the cooling fluid. However,the working string 230 will most likely need to be insulated near thesurface 102 to prevent a significant loss of cold energy to thenear-surface strata 104.

As an alternative, the surface refrigeration system is augmented or evenreplaced by a gas compression system and a downhole expansion valve 234.It is known that certain compressed gases when expanded through a valveundergo significant cooling. Use of a downhole expansion valve 234 tocause cooling of the circulating fluid has the benefit of removing orsignificantly reducing “cold energy” losses to the overburden (that is,the near-surface strata 104) while transporting the cooling fluid fromthe surface 102 to the subterranean zone 106. In addition, use of adownhole expansion valve 234 reduces or even removes the need forwellbore insulation along the near-surface strata 104 as the coolingfluid need not be completely chilled prior to injection.

In operation, gas is compressed in the gas compression system at thesurface 102. The compressed gas is then cooled to near-ambienttemperature via air or water cooling. In some cases, the gas may befurther cooled via refrigeration. None, some, or all of the fluid may bein a condensed state after the cooling steps. The cooling fluid is thensent down the bore 235 of the working string 230, and through theexpansion valve 234. This causes the fluid to cool via the Joule-Thomsoneffect.

Preferably, the expansion valve 234 is just above or within thesubterranean zone 106. The cooling fluid is allowed to absorb heat fromthe surrounding formation, which in turn leads to ice formation withinthe subterranean zone 106. Preferably, the cooling fluid is at atemperature of about −20° F. to −120° F. after passing through theexpansion valve 234. More preferably, the cooling fluid is at atemperature of about −20° F. to −80° F. after passing through theexpansion valve 234. More preferably still, the cooling fluid is at atemperature of about −30° F. to −60° F. after passing through theexpansion valve 234.

Preferably, the cooling fluid is at a pressure of about 100 psia to2,000 psia before passing through the expansion valve 234, and about 25psia to about 500 psia after passing through the expansion valve 234.More preferably, the cooling fluid is at a pressure of about 200 psia to800 psia before passing through the expansion valve 234, and about 40psia to about 200 psia after passing through the expansion valve 234.

As noted, the expansion valve 234 may be placed along the working string230 in the cooling well 220A at different locations. In addition, morethan one expansion valve 234 may be used. FIG. 2B is a cross-sectionalview of a cooling well 220B, in an alternate embodiment. In this coolingwell 220B, two expansion valves 234′ and 234″ are placed along thehorizontal portion 206 of the bore 225 and within the subterranean zone106. In this arrangement, both expansion valves 234′, 234″ are withinthe bore 235 of the working string 230.

The use of two expansion valves 234′ and 234″ permits a more uniformcooling temperature along the horizontal length of the cooling well 220Bthan would be possible with a single expansion valve. This, in turn, maylead to a more uniform impermeable barrier 108 over the subsurfaceformation 110 targeted for production.

In operation, a first temperature drop is accomplished as the coolingfluid moves through the first expansion valve 234′. The cooling fluidthen imparts cold energy to the subterranean zone 106 on the way down. Asecond temperature drop is then accomplished as the working fluid movesthrough the second expansion valve 234″. The working fluid may thenimpart additional cold energy to the subsurface formation 106 on the wayback up the annulus 232.

It is noted that the relative placement of valves 234″ and 234″ is amatter of designer's choice. In addition, the sizing of the innerdiameters of the expansion valves 234′, 234″ is a matter of designer'schoice. The placement and the sizing of the expansion valves 234′, 234″may be adjusted to provide for selective pressure drops. In one aspect,the cooling fluid is at a pressure of about 800 psia to 3,000 psiabefore passing through the first expansion valve 234′, 500 psia to 2,000psia before passing through the second expansion valve 234″, and about25 psia to 300 psia after passing through the second expansion valve234″. More preferably, the cooling fluid is at a pressure of about 800psia to 2,000 psia before passing through the first expansion valve234′, about 100 psia to about 500 psia after passing through the firstexpansion valve 234′, and about 25 psia to 100 psia after passingthrough the second expansion valve 234″.

In the cooling well 220B of FIG. 2B, both expansion valves 234′ and 234″create a Joule-Thompson effect for the cooling fluid within the bore 235of the working string 230. However, it is feasible to provide one orboth of the pressure drops outside of the bore 235. This would involveplacement of one or both of the valves between the bore 235 and thesurrounding casing 230, that is, within the annulus 232 along thehorizontal portion 206 of the cooling well 220B.

When using downhole expansion valves, a number of cooling fluids aresuitable. Suitable fluids may include C₂-C₄ hydrocarbons (e.g., ethane,ethylene, propane, propylene, isobutane, and n-butane) or mixturescontaining a majority of one or more of these components. Other suitablecomponents may include refrigerant halogenated hydrocarbons, carbondioxide, and ammonia. The specific compositional choice for a coolingfluid depends on a number of factors including working pressures,available pressure drop through the valve, thermodynamic behavior of thefluid, temperature limits of the metallurgy of the conduits, safetyconsiderations, and cost/availability considerations. Additionaltechnical descriptions of working fluids and their uses in formingfreeze walls have been described in U.S. Pat. Nos. 7,516,785 and7,516,787. These patents also disclose additional cooling wellembodiments. These patents are assigned to ExxonMobil Upstream ResearchCompany, and are incorporated herein by reference in their entireties.

It is optional to provide insulation to the elongated working string 230above the subterranean zone 106. In addition, the operator may employ anelongated U-tube as the working string. The U-tube provides a closedsystem through which the cooling fluid flows.

Still another option for forming an impermeable barrier 108 involves theuse of electrokinetic deposited barriers. Electrokinetic barriers arethin, impermeable barriers formed by forced metal dissolution, ionmigration, and precipitation. U.S. Pat. Publ. No. 2006/0163068 entitled“Method for Soil Remediation and Engineering,” describes anelectrokinetic method for groundwater protection. The method comprisesapplying an electric field across an area of soil so as to generate a pHand Eh gradient, and thereby promote the in situ precipitation of astable iron-rich band. According to the published application, themethod may be performed for, inter alia, the purpose of forced anddirected migration of contaminated leachates.

In another example described by Faulkner et al., Mineralogical Magazine,pp. 749-757 (October 2005), electrically stimulated iron rods may beplaced in close relation within the subterranean zone 106. The approachwas developed for contamination confinement. Preferably, the rods areoriented horizontally along the plane of the subterranean zone 106 toreduce the number of rods required.

A preferred embodiment for forming the impermeable barrier 108 involvesthe injection of a polymer solution. The polymer solution is injected ina liquid phase, but sets as an extremely viscous fluid, a stiff gel, oreven as a solid. In one aspect, the polymer solution is a cross-linkedpolymer solution that slowly reacts in situ to form a substantiallysolid material or gel. The slowly cross-linking polymer solution isinjected into injection wells 120. The polymer solution spreads out overdays or weeks within the subterranean zone 106. The polymer solutionthen sets within the subterranean zone 106 as a gel.

To limit vertical migration and to help ensure coverage, the injectedpolymer solution fluids may optionally be flowed to production wells(not shown) that are completed at similar depths to the service wells120. In addition, the cross-linked polymer solution may include a densesoluble material such as a salt. Use of a dense fluid helps to limitupward migration of the polymer solution and to promote its spreading asa relatively thin layer over the viscous oil deposit. In this way, aneffective topseal, that is, a largely impermeable barrier tolow-pressure fluid flow covering an extended area, is formed.

In another embodiment, the injected fluid is a temperature-sensitivesolution that cools within the subterranean zone 106 and hardens insitu. FIG. 3 presents a flow chart demonstrating a method 300 ofplugging a subterranean zone above a subsurface formation using such afluid. The method 300 employs a specially formulated waxy emulsion thatis designed to be heated for injection into the subterranean zone 106.The composition comprises a water-in-oil emulsion with added wax toadjust the melting range. The emulsion fills the pores in the permeablesubterranean zone 106, and hardens into a solid as it cools. In thisway, the subterranean zone 106 is plugged to form an extended topseal.

In accordance with the method 300 of FIG. 3, the operator of thereservoir (or a contractor or consultant) first formulates the waxyemulsion. This is shown generally at Box 310. The emulsion is a blend ofliquids comprising oil, added wax, and water. An emulsifying agent andsolvent may optionally be added to adjust the viscosity of the emulsion.The composition of the emulsion is designed so that the mixture will bea liquid above a targeted temperature, but gels or solidifies into awaxy matrix containing water droplets once the emulsion cools to belowits melting range. In the present application, the melting range must beabove the temperature experienced by the waxy matrix if heated vaporfrom the subsurface formation 110 contacts the subterranean zone 106during the in situ recovery of viscous oils.

In one aspect, the emulsion is formulated to have a viscosity greaterthan that of any fluids residing within the zone 106 to be plugged. Inthis way, the injected emulsion efficiently displaces the in situfluids, thus enhancing the ability to achieve effective plugging.

To operate in this manner, various reservoir characteristics and fluidfactors are simultaneously considered. One factor is the temperature ofthe subterranean zone 106. The emulsion is formulated to have a meltingpoint above this temperature. Another factor is the pressure rangewithin the subterranean zone 106. A minimum gel strength required forthe emulsion is deduced from the pressure prevailing within the zone106. The operator may also consider the volume of the high permeabilityzone 106 to be plugged. This will determine the desired amount of waxyemulsion to be injected into the target zone 106. Sufficient emulsionvolume is injected through the service wells 120 to reach a desiredradius for the estimated void volume in the subterranean zone 106. Theoperator injects the desired volume, plus a volume sufficient to fillthe injection tubing of the service well 120.

Next, the viscosity of fluids in the target zone 106 is preferablydetermined. The purpose of the viscosity determination is to determine adesired viscosity for the waxy emulsion. The viscosity of the emulsionshould be similar to or, preferably, greater than that of any residentfluids in the subterranean zone 106. Also, an oil may be selected forthe waxy emulsion. The oil may be any oil that, when mixed with wax,makes a mixture that emulsifies with water in the presence of anemulsifying agent. The oil is preferably crude oil.

The emulsion will also include a wax. It is noted that in some producedcrude oils, paraffins or other waxes may already be present in theproduction stream. However, such wax content may not be enough to causea solidification of the emulsion at the anticipated subterranean zone106 temperature. Therefore, the wax may be at least in part a waxadditive or added wax. The added wax may be selected from a wide rangeof waxes that are soluble in oil. Examples include petroleum-derivedwaxes such as paraffins, or non-petroleum natural waxes, such as beeswaxor vegetable wax. Numerous suppliers offer paraffin and non-paraffincontaining hydrocarbon-based wax stocks that could be utilized in thecurrent processes. One preferred source for wax is Imperial Oil Limited.The Imperial Oil Slack Wax product line provides various waxes with abroad range of melting points and physical characteristics for use asblending components.

The composition of the wax-oil mixture is chosen so that the waxyemulsion is liquid above a targeted temperature, but solidifies once theemulsion cools to below its melting range. Two variables generallydetermine the melting range of the hydrocarbon phase of the injectedemulsion. These are the fraction of wax included, and the melting rangeof the individual wax component. A wax is selected that has a congealingpoint (the highest temperature of the melting range) sufficiently highso that mixtures of approximately one-half wax and one-half oil willhave a melting range lower than the injection temperature, but higherthan the desired stable operating temperature. The wax-oil mixture mayhave a congealing point of approximately 20° C. to about 80° C. abovethe temperature in the subterranean zone 106.

Additional details for selecting a wax and for formulating a wax-oilmixture is disclosed in co-owned WO 2008/024147, entitled “Compositionand Method for Using Waxy, Oil-External Emulsions to Modify ReservoirPermeability Profiles.” This published patent application isincorporated herein by reference in its entirety.

In one manner of formulation under Box 310, a series of mixtures of aselected wax and oil are prepared. The melting range of each mixture isempirically measured. The preferred method for measuring the meltingrange is to measure viscosity versus temperature in a rheometer, such asthe Viscoanalyzer VAR 100™ manufactured by Reologica Instruments, or theHBDV-III viscometer, manufactured by Brookfield Instruments. The meltedsample is placed in the instrument at a temperature above the meltingrange, and the viscosity is measured versus shear rate for a series ofdecreasing temperatures. As the temperature drops below the uppertemperature of the melting range, the viscosity of the wax-oil mixtureincreases dramatically, indicating the melting range.

The measured value of the lowest temperature of the melting range, thatis, the temperature at which total solidification occurs, may varydepending upon the method used. For example, a scanning differentialcalorimeter often reveals a lower solidification temperature than visualor rheometric measurements. However, for purposes of applying theplugging method 300, precise measurement of the solidification point isnot required. Measuring the temperature at which wax crystals are firstnoted is sufficient, and the fluid composition is designed and theinjection temperature is controlled based on that temperature. While thewaxy emulsion may continue to be injected and flow through porous rockat temperatures below this upper temperature limit of the melting range,designing the system so that this limit is not reached by the fluidprior to entering the subterranean zone 106 ensures that the process iseffective.

If a viscous, heavy crude oil is chosen as the oil, it may be desirableto add a solvent to the emulsion. The addition of diluent solventreduces the hydrocarbon phase viscosity. This, in turn, reduces theviscosity of the injected emulsion, as the viscosity of the emulsion isprimarily controlled by the viscosity of the external hydrocarbon phase.Different solvents may be used to reduce the viscosity of the emulsion.Examples include kerosene and Varsol™. Varsol™ is a product of ImperialOil Limited. Varsol™ (a refined middle distillate) is commercially usedfor automotive cleaning to remove oil and grease. It is also used forthinning oil-based paints, varnishes, and polyurethanes.

Depending on the composition of the wax-oil mixture, changes inviscosity and melting range due to the addition of solvent may or maynot be significant. Empirical measurements may be made on mixtures todetermine the impact of diluent solvent addition. By making measurementsof viscosity and melting range for various possible mixtures, theoperator may choose a composition that meets the desired viscosity andmelting range. Preferably, the actual target viscosity of thehydrocarbon blend is chosen so that when a waxy emulsion is madecontaining approximately 40 to 60 volume % of water, the emulsion has aviscosity approximately 1.25 to 3 times greater than that of the fluidsresiding within the subterranean zone 106 to be plugged. This ensuresthat the emulsion has a favorable mobility ratio displacement of thefluid existing within the high permeability zone 106 to be plugged,while still maintaining a viscosity low enough to be injected easily.Such a favorable mobility fluid will more effectively displace theresident fluid and achieve a more uniform plug that better conforms tothe volume distribution of the high permeability zone after cooling.

In addition to a solvent, the operator may optionally choose to add anemulsifying agent. Surfactants may be used as emulsifying agents. Thesurfactants may be either ionic or non-ionic. If surfactants are used,the surfactant type and concentration should be chosen so that themixture forms an oil-external emulsion with water droplets havingdiameters of approximately 1 to 10 microns. Water droplets with largerdiameters tend to be less stable and may rupture during injection intothe reservoir. Therefore, they are not recommended.

The operator may also determine a desired water content for the waxyemulsion. By definition, the emulsion includes not only oil, but atleast some water. The emulsion formed is a water-in-oil emulsion. Wateris desirable in the emulsion for several reasons. First, including waterin the injected fluid significantly reduces the cost per volume of thefluid, because water is significantly less expensive than oil or otheradditives. Second, the water, included as internal droplets in anoil-external emulsion, produces a fluid which has significantly higherviscosity than that of either the individual oil or water phases. Theviscosity of the emulsion may be adjusted by varying the water content.Therefore, the resulting emulsion may be designed to have favorablemobility displacement of any water in the subterranean zone 106. Third,the presence of water increases the heat capacity of the injected fluid,allowing the injected fluid to retain heat for a longer period comparedto a single-phase wax. Because water has a higher specific heat capacitythan oil, including water as the internal phase allows the injectedfluid to have a greater heat capacity. This also allows the injectedfluid to cool more slowly and penetrate into the zone 106 farther thanif oil were the sole phase injected.

The method described in Box 310 of FIG. 3 allows the injection of a waxyemulsion in liquid form to achieve effective penetration into thesubterranean zone 106 at distances from the service wells 120. Themethod of Box 310 also provides for adjusting the fluid viscosity duringinjection by changing the solvent or water content to provide favorablemobility displacement of fluids residing in the zone 106 duringplacement. Because of the presence of added wax in the emulsion, theemulsion will have a melting range that is above a targeted temperature.Thus, after a period of curing, a solidified plug is created that mayprovide an artificial barrier 108 to escaping vapors.

Referring again to FIG. 3, the plugging method 300 also involvesblending the waxy emulsion. This is shown at Box 320. The hydrocarbonphase components (wax, oil, and any added diluent solvent (if desired))are mixed in a suitable storage tank. Alternatively, separate supplytanks of the wax, oil, and solvent may be used, and the componentscontinuously mixed in-line during injection, so that the desired finalcomposition is maintained within specifications. To blend the emulsion,the hydrocarbon mixture is blended and sheared, together with anyemulsifying agent and the selected volume ratio of water, in a suitablemixing device such as an in-line blender.

During storage of liquids and subsequent mixing, the tanks and surfaceflow lines may be heated and insulated to maintain the temperature ofthe liquids. Preferably, the temperature of the liquids is maintained atapproximately 20° C. to 80° C. above the melting range of the waxyemulsion. The emulsion may then be mixed on the surface using pre-heatedfluids. The emulsion may optionally be further heated after mixing.Thus, blending 320 encompasses any heating process for obtaining atemperature of the final emulsion blend that is above the melting rangeof the emulsion.

It may be desirable to also heat the service well 120 before injectingthe waxy emulsion into the subterranean zone 106. An optional wellboreheating step is shown at Box 330. Heating may be accomplished bycirculating steam through the injection string and back up the annulus.Depending upon the injection well completion design and its temperatureprofile from surface to the bottom of the service well 120, steam mayalso be injected into a portion of the subterranean zone 106 prior toinjecting the emulsion. This raises both the wellbore and subsurfacetemperatures to above the melting range of the emulsion. This helpsprevent premature cooling and solidification of the emulsion.

After sufficient heating of the waxy emulsion and, optionally, thewellbore, the emulsion is injected into the service well 120 andsurrounding subterranean zone 106. The plugging agent is injected as aheated, liquid emulsion wherein the hydrocarbon phase contains a waxcomponent. The injection step is indicated at Box 340. Upon injection,the emulsion fills the pore spaces of the subterranean zone 106.

During the injection step of Box 340, sufficient waxy emulsion volume isinjected to reach a radius of investigation desired to fill the highpermeability region to be plugged or the estimated void volume. Thepreferred injection mode is to inject the waxy emulsion as fast aspossible without exceeding the formation fracture pressure until thedesired volume is injected. Injecting at slower rates result in lessinvasion due to decreasing fluid mobility and increasing flow resistancecaused by the formation of a wax structure in the emulsion as thetemperature cools into and below its melting range. Because the emulsionis a heated liquid, injection pressure during the injection in Box 340may not rise significantly above the formation pressure.

Following injection of the waxy emulsion, a small volume of fluid may beinjected to displace the tubing volume from surface to the injectiondepth. This displacement is shown at Box 350 of FIG. 3. The fluid isinjected to displace any emulsion within the injection string that maysolidify and plug the string following shut down. The fluid ispreferably steam.

After the displacement step in Box 350, the subterranean zone 106 isallowed to cool. The purpose is to cure the waxy emulsion in situ. Thiscuring step is shown in Box 360. Curing 360 is accomplished by shuttingin the service well 120. The well 120 should remain shut in for a periodof time estimated from experimental data and computations to besufficient to allow the injected emulsion within the zone 106 to cool tobelow its melting range and reach the desired gel strength. The operatorshould determine the period for curing based upon the anticipatedtemperature profile of the subterranean zone 106 and the expected rateof cooling of the injected emulsion. Because the subterranean zone 106is typically relatively shallow, cooling should take place fairlyquickly, such as within 2 to 5 days.

Once in place within the target zone 106, the waxy emulsion cools to atemperature below its melting range. Upon cooling below the meltingrange, the external hydrocarbon phase surrounding the water dropletswithin the emulsion solidifies, forming a topseal.

Following curing in Box 360, the operator may optionally circulate aheated cleaning fluid. This is represented by Box 370. The cleaningfluid will be oil or an emulsion of oil, water, and perhaps, solvent.Alternatively, only a solvent could be used. Kerosene or other middledistillates, preferably containing some aromatic components, may beused. The heated fluid serves to melt and clean out any solidifiedplugging agent remaining within the service wells 120.

During circulation in Box 370, some plugging agent will be returned tothe surface 102. The used waxy emulsion is collected for either recoveryor disposal. The service wells 120 are then shut in.

In an alternate embodiment of the invention, one or more additionalinjections of the waxy emulsion are made after curing in Box 360. Theinjections are referred to as “squeezes.” The injection in Box 340,displacement in Box 350, cooling in Box 360, and circulating in Box 370together may be designated as the first squeeze. Preferably, two or moreadditional squeezes of the waxy emulsion are conducted sequentially toeffectively plug the high permeability zone 106.

Following the cooling period in Box 360 and, optionally, the circulatingin Box 370, another volume of waxy emulsion is injected as part of asecond squeeze. Injection is intended to fill any voids remaining afterthe first injection in Box 340, and to fill additional high permeabilitypathways not contacted by the first injection. Injection pressure duringthe second (and optional third) injection typically rises significantlyabove that observed during the first injection. Injection may becontinued until a sufficiently high pressure is reached or the desiredadditional volume is injected. Again, the injection pressure should notexceed the fracture pressure for the formation.

The terminal pressure should be held for several hours by shutting ininjection, allowing the pressure to partly decline, and then refillingthe injection string with additional waxy emulsion to maintain anelevated pressure on the squeeze. After the rate of pressure decline hasslowed, indicating that the emulsion is beginning to solidify andprovide more flow resistance, another small volume of oil may beinjected to just displace the tubing volume from surface to theinjection depth. This is shown at Box 370. The service wells 120 areagain shut in to allow the emulsion to cool and solidify.

After the final waxy emulsion injection, a cleanup operation may beconducted. This is in accordance with Box 380. Heated oil or solvent iscirculated through the service wells 120 to remove solidified pluggingagent in and near the wellbore.

A benefit of the use of the waxy emulsion as the plugging agent for theartificial barrier 108 is that the solidified waxy emulsion may besubstantially removed from the subterranean zone 106 at a later time. Inthis regard, after the in situ recovery process for viscous oils fromthe subsurface formation 110 is completed, the heated oil or other hotcleaning fluid may be circulated within the service wells 120 to bringthe temperature in the subterranean zone 106 up through the meltingrange of the emulsion. After the waxy emulsion has been re-liquefied,the emulsion may then be at least partially swept out from thesubterranean zone 106 through injection of steam. Selected injectionwells will be converted to production wells to produce the emulsion backto the surface.

Another option for forming an impermeable barrier 108 relates to theplacement of a solidifying fluid into the subterranean zone 106. Thesolidifying fluid is injected into the subterranean zone 106, where itchemically reacts in situ to form a solid precipitate. This leads topore plugging and permeability reduction of the formation rock in thesubterranean zone 106. A number of in situ precipitation methods havebeen proposed for modifying local permeability in a subsurface reservoirso to reduce flow into wells. Examples of such methods are disclosed inU.S. Pat. No. 3,684,011, U.S. Pat. No. 3,730,272, U.S. Pat. No.4,002,204, U.S. Pat. No. 5,244,043, and U.S. Pat. No. 6,401,819, each ofwhich is incorporated herein by reference. Such methods may formprecipitates from salts of metals, sulfates, bicarbonates, asphalts, ororganic substances. In some embodiments, the precipitation or gellingchemistry may be chosen to be temperature-sensitive such thatpermeability reduction occurs or increases when heat from a recoverymechanism interacts with the fluids which were injected to form abarrier.

Referring again to FIG. 1A, the oil field 100 targets the subsurfaceformation 110 containing viscous hydrocarbons such as bitumen. Theviscous hydrocarbons are in an unheated and immobile state. However, itis desired to recover the viscous hydrocarbons from the subsurfaceformation 110 by heating the viscous hydrocarbons in order to convertthem to a mobilized and producible state. Heating of the subsurfaceformation 110 may reduce viscosity of in situ hydrocarbons from a valuesubstantially greater than 1,000 cp to substantially less than 100 cp.

In FIG. 1A, it can be seen that two sets of wells are completed in thesubsurface formation 110. Each set contains at least one heat injectionwell 130 and at least one production well 140. The wells 130, 140 areslightly offset in FIG. 1A for visibility purposes. The heat injectionwells 130 are used for injecting steam or other heated vapor into thesubsurface formation, while the production wells 140 are used forproducing mobilized hydrocarbon and condensed steam.

Preferably, each set of wells 130, 140 represents a pair of wells,meaning one heat injection well 130 with one production well 140, asshown in FIG. 1A. In addition, it is preferred that both the heatinjection well 130 and the production well 140 be completed horizontallyto elongate the heating and production aspects of the wells 130, 140.This is demonstrated in FIG. 1A, with the wellbores forming the heatinjection 130 and production 140 wells illustratively extending out ofthe page.

The subsurface formation 110 has an upper portion 114 and a lowerportion 116. Preferably, the horizontal portions of the heating 130 andproduction 140 wells are completed in the lower portion 116 of thesubsurface formation 110. As steam or other heated vapor is injectedthrough the heat injection wells 130 and into the subsurface formation110, the vapor will rise through the subsurface formation 110. Further,as the viscous hydrocarbons in the subsurface formation 110 aremobilized, they will drain by operation of gravity towards the bottom ofthe subsurface formation 110. Therefore, placement of both the heatingwells 130 and the production wells 140 at the lower portion 116 of thesubsurface formation 110 is preferred.

FIGS. 1A through 1F together show the process of heating the subsurfaceformation 110 and then recovering mobilized hydrocarbons. In FIG. 1A, noheating has yet taken place in the subsurface formation 110. In FIG. 1B,steam or other heated vapor has begun to be injected into the subsurfaceformation 110 through the heat injection wells 130. Viscous oils arebeing heated in a small but growing steam chamber 135.

The heated fluid being injected into the steam chamber 135 has atemperature considerably higher, e.g. 150° F. to 1,000° F., than thetemperature of the subsurface formation 110 into which it is injected.The heated fluid could be a heated gas or liquid such as steam, and mayalso contain surfactants, solvents, oxygen, air, and inert inorganicgases. However, because of its high heat content per unit mass, steam isideal for raising the temperature of a reservoir and is especiallypreferred for practicing the inventions disclosed herein. Thus, theamount of heat that is released when steam condenses is very large.Because of this latent heat, viscous oil reservoirs may be effectivelyheated.

The operator may pre-determine a volume of steam to be injected. Severalfactors will affect the volume of steam. Among these are the thicknessof the hydrocarbon-containing formation 110, the viscosity of thebitumen or other oil-in-place, the porosity of the formation, thesaturation level of the hydrocarbon, water in the formation, and thefracture pressure. Generally, the total steam volume injected may varybetween about 1 and 5 liquid equivalent barrels per barrel of oilproduced.

Various ways may be employed for initiating a steam injection process.In the beginning, steam may optionally be injected into the subsurfaceformation 110 through both the injection wells 130 and the productionwells 140. Alternatively, heated vapor may be injected into thesubsurface formation 110 only through the heat injection wells 130, butalso circulated within the production wells 140. Circulation of heatedvapor within the wellbores of the production wells 140 increases thetemperature of the subsurface formation 110 around the production wells140 through thermal energy.

FIG. 4 is a cross-sectional view of a pair of wells, representing a heatinjection well 430 and a production well 440, in one embodiment. Thewells 430, 440 are placed within subsurface strata of an oil field 400.As with FIGS. 1A and 1B, the subsurface strata of the oil field 400 ofFIG. 4 include near-surface strata 104 and subterranean zone 106. Anartificial barrier 108 is again in place in the subterranean zone 106 inorder to provide a topseal.

The subsurface strata of the oil field 400 also includes a subsurfaceformation 410 having viscous oil. In this illustrative arrangement, thesubsurface formation 410 is a tar sand deposit. The heat injection well430 and the production well 440 are completed in a lower portion 416 ofthe tar sand deposit

In the arrangement of FIG. 4, the production well 440 is completedsubstantially horizontally. In this respect, the production well 440includes a horizontal portion 446 that extends along the lower portion416 of the tar sand deposit 410. The horizontal portion 446 ispreferably drilled so that it extends along the fracture trend of theformation containing the tar sands deposit 410.

The production well 440 is completed with a perforated or slotted casing442. In addition, the production well 440 has concentric inner tubingstrings 443 and 444 within the slotted casing 442. The concentric tubingstrings 443, 444 terminate inside of the casing 442 at a level near thelower portion 416 of the tar sands deposit 410. However, the horizontalportion 446 of the production well 440 with the slotted casing 442extends well past the tubing strings 443, 444 and along the tar sandsdeposit 410. This manner of completion together with the appropriateproduction rate helps to ensure that a relatively high oil saturationexists adjacent to the horizontal portion 446 so that the horizontalportion 416 of the production well 440 remains full of liquid.

As noted, the oil field 400 also includes a heat injection well 430. Inthe arrangement of FIG. 4, the heat injection well 430 is completedsubstantially vertically, although in other embodiments the well may bedeviated or horizontal. The heat injection well 430 extends to near thetop of the horizontal portion 446 of the production well 440.Preferably, the bottom of the heat injection well 430 will extend towithin about 5 to 10 feet from the top of the horizontal portion 446 ofthe production well 440, but depending on the nature of the tar sanddeposit 410 may be as far as 100 feet. Smaller clearances will be usedif it is desired to achieve thermal communication without fracture or ifthe direction of fractures is hard to predict.

The heat injection well 430 is completed with a slotted liner 432 forsteam injection. In operation, steam (or other heated vapor) is injectedinto the formation via well 430 below the fracture pressure of theformation 410 holding the tar sands deposit. Mobilized heavy oil drainstowards the nearly horizontal portion 416 of well 440. Tubing strings443 and 444 terminate at a distance which is calculated to maintain themain horizontal portion 416 of the production well 440 full of liquidwith throttled production.

It is noted that the while the illustrative production well 440 iscompleted with two concentric strings of tubing 443, 444, in many casesa dual tubing completion will suffice. The use of a third tubing stringallows an insulating gas to be introduced into the annulus between theinner two tubing strings, but this is an optional feature.

The described configuration of wells 430, 440 promotes separate oil andwater flowpaths, thereby maintaining high oil relative permeability. Inaddition, any non-condensable gases which may accumulate in the tarsands deposit 440 may be purged near an upper portion 414 of the tarsands deposit 440 via an outer annulus of the production well 440 viathe slots in casing 442. These slots extend up the casing 442 to nearthe upper portion 414 of the reservoir.

It is noted that the producer may elect not to fracture the formationholding the tar sands deposit 410. This may be desirable for thedrainage of oil from oil sands that are not very deeply buried and wherefracturing may be uncontrollable or where fluid communication may beestablished without fracturing. The technique may also be used where itis desired to drill the horizontal production well 440 in a directionother than along a fracture trend. For example, the operator may desireto drill perpendicularly from the shore of a small lake which containsan oil sand reservoir beneath it. In such cases, it is particularlydesirable to have the injection well 430 closer than usual to thehorizontal portion 416 of the production well 440 so that initialthermal communication may be established fairly rapidly by thermalconduction.

It is understood that the current inventions are not limited to the typeof recovery process as long as it maintains the physical integrity ofthe barrier. In practice, this will generally mean the recovery processutilizes relatively low pressures, e.g., non-fracturing pressures, so asnot to rupture the relatively thin and, possibly, gel-like, artificialtopseal barrier. For example, a low pressure steam flood may be appliedas the recovery process where steam is continuously flowed from aninjection well to a production well. Furthermore, other arrangements forpairs of wells may be employed. Examples of such arrangements aredescribed in U.S. Pat. No. 4,344,485 mentioned above in the Backgroundsection. FIG. 2 of the '485 patent displays a production well (10)completed horizontally below a horizontally completed heat injectionwell (11). FIG. 3 of the '485 patent depicts a production well (40) anda heat injection well (41), wherein each well is completed vertically.The '485 patent, including these drawings, is incorporated herein byreference in its entirety.

In any of these arrangements, steam is injected into the subsurfaceformation at pressures and rates sufficient to create a large steamchamber to cause gravity drainage of the mobilized heavy oil. Injectionpressures are usually within the range of about 50 to 1,000 psig, andpreferably about 100 to 600 psig, during the oil recovery phase. Ofcourse, lower pressures may be employed if a pump such as a conventionalsucker rod pump or, preferably, a chamber lift pump, is provided at thebottom of the production well.

Referring now to FIG. 1C, FIG. 1C provides another side view of the oilfield 100. Here, steam or other heated vapor continues to be injectedinto the subsurface formation 110. It can be seen that the steamchambers 135 continue to grow away from the heat injection wells 130.The steam chambers 135 produce condensate, both from injected gas andfrom mobilized viscous oils in the subsurface formation 110.

In addition to the steam chambers 135, oil drainage layers 145 have alsobeen formed. The oil drainage layers 145 represent areas of lesserpressure around the steam chambers 135, where viscous oils have beenmobilized into flowable heavy oil. The flowable heavy oil flows aroundand through the steam chambers 135 and into the production wells 140,primarily by means of gravity drainage. Thus, this represents alow-pressure production method.

It is noted that once sizeable steam chambers 135 have been establishedsuch as is shown in FIG. 1C, it may be desirable to reduce the steaminjection pressure. For example, it may be desirable to operate atformation pressures significantly below the fracture pressure. Thisrepresents another aspect of a low-pressure production method. Injectionpressure is limited to the fracture pressure, which may be as low asbetween about 50 and 200 psia.

FIG. 1D presents another cross-sectional view of the subsurface stratafrom the oil field 100. Here, heated vapor continues to be injected intothe subsurface formation 110. The steam chambers 135 continue to expandabove and away from the heat injection wells 130. In the view of FIG.1D, the steam chambers have reached the top of the subsurface formation110. Beneficially, the artificial barrier 108 is acting as a topseal,preventing the vertical migration of steam out of the subsurfaceformation 110. Small oil drainage layers 145 remain at the tops of thesteam chambers 135.

FIG. 1E provides yet another side view of the oil field 100. Here, steamor other heated vapor continues to be injected into the subsurfaceformation 110. It is understood that the heated injectant will risewithin the subsurface formation 110, causing mobilization of viscoushydrocarbons in the upper portion 114 of the hydrocarbon formation 110before the lower portion 116.

It can be seen in FIG. 1E that the steam chambers 135 have substantiallyfilled the upper portion 114 of the hydrocarbon formation 110. The oildrainage layer 145 above the steam chamber 135 is almost gone,indicating successful mobilization of viscous hydrocarbons up to theartificial barrier 108. In addition, the steam chambers 135 haveessentially merged into a single steam chamber.

Because the steam chambers have merged into a single chamber 135, asingle oil drainage layer 145 is also formed. Heavy oil flows from theoil drainage layer 145 into the production wells 140.

It is noted that the temperatures and pressures associated with thesteam injection and corresponding viscosity reduction are effective inrecovering a substantial portion of the viscous oils in situ. The steamchambers 135 may be created at a temperature range of about 350° C. downto about 150° C., depending on the in situ pressure. However, suchtemperatures and accompanying injection pressures may not be compatiblewith the material forming the artificial barrier 108 throughout the lifeof the operation. For example, if the artificial barrier is a frozenbarrier or a temperature-sensitive polymer, then the operator may needto discontinue steam injection as the steam chamber 135 approaches thesubterranean zone 106.

The operator may monitor temperatures in the subterranean zone 106 usingsensors placed in the service wells 120. If the operator receivesfeedback suggesting that the temperature is approaching a melting pointof the plugging material forming the artificial barrier 108, then steaminjection may be discontinued.

In order to recover an additional amount of oil from the subsurfaceformation 110, the operator may choose to inject a light hydrocarbonsolvent into the previously formed steam chambers 135. The solvent is inthe C₃ to C₁₀ range of components, and more preferably in the C₃ to C₅range.

FIG. 1F provides a final cross-sectional view of the subsurface stratafrom the oil field 100. Here, a light hydrocarbon solvent is beinginjected into the subsurface formation 110 through the heat injectionwells 130. The solvent may be mixed with steam to form the heated vapor.In any instance, the heated vapor has caused the steam chamber 135 tosubstantially fill the hydrocarbon formation 110. The production wells140 continue to receive heavy oil from the oil drainage layer 145through gravity.

Given the low operating pressures in the subsurface formation 110, thesole use of steam to reduce the viscosity of the in situ oil may beimpractical, even during earlier phases of oil recovery. The addition orsubstitution of solvent may enhance viscosity reduction. Moreover, asnoted, if the integrity of the topseal (artificial barrier 108) istemperature-sensitive, solvents may permit the use of temperaturessignificantly lower than that of pure steam. In some embodiments,solvents (with no steam) largely in the C₃ to C₅ range may be injectedin a heated vapor state. The solvents will condense in situ at about 30°C. or less at shallow in situ pressures. In situ temperatures of shallowbitumen resources in Canada are typically 10° to 15° C.

It is also noted that the use of light hydrocarbon solvents may providesome degree of in situ upgrading of the heavy oil. Solvents mayprecipitate out a portion of low-value asphaltene components in certainviscous oils.

In lieu of steam or heated solvents, the operator may choose to useother heating methods for the subsurface formation 110. For example, theheat injection wells 130 may be part of an electric heating arrangement.Several ways of performing electrical heating of viscous oil depositshave been described, including electrical wellbore heaters.

U.S. Pat. No. 3,149,672 is entitled “Method and Apparatus for ElectricalHeating of Oil-Bearing Formations.” In the '672 patent, an electricalcurrent is passed between sets of fractures that are propped withelectrically conductive particles. One set of fractures may be in anupper portion of a formation, while the other set may be in a lowerportion of the formation. Passing the electrical current through theformation generates electrically resistive heat. The purpose is to warm“viscous oil.”

The teachings of the '672 patent are referred to and incorporated hereinby reference in their entirety. Also, a method of resistively heating aformation by passing electricity between wellbore electrodes in theformation has been discussed in Paper 2008-209, “Electro-Thermal Pilotin the Athabasca Oil Sands: Theory Versus Performance,” CanadianInternational Petroleum Conference (2008).

U.S. Pat. No. 7,331,385 is entitled “Methods of Treating a SubterraneanFormation to Convert Organic Matter into Producible Hydrocarbons.” Thisco-owned patent involves a process of heating organic matter in asubsurface formation in-situ to create and recover produciblehydrocarbons. The formation may contain a solid organic matter such askerogen, in which case heating causes pyrolysis of the solid matter.Alternatively, the formation contains heavy oil or tar sands, in whichcase heating causes a substantial reduction in fluid viscosity.

In the methods of the '385 patent, the formation is fractured from oneor more wells. Subsequently, an electrically conductive material isinjected into the fractures. The conductive material may be a proppantsuch as (i) thinly metal-coated sands, (ii) composite metal/ceramicmaterials, or (iii) carbon based materials. Alternatively, theconductive material may be a non-proppant such as a conductive cement.Sufficient heat is generated by electrical resistivity through theconductive material to pyrolyze at least a portion of the solid organicmatter into producible hydrocarbons, or to reduce the viscosity of atleast a portion of the heavy hydrocarbons. The teachings of the '385patent are also referred to and incorporated herein by reference intheir entirety.

Another heating method involves circulating hot fluids throughclosed-loop wells. U.S. Pat. No. 3,994,340 is entitled “Method ofRecovering Viscous Petroleum From Tar Sand.” This patent mentions thecirculation of a hot fluid through a wellbore as a means of reducingviscosity of “viscous petroleum.”

In another arrangement, the heat injection wells 130 may employresistive heaters placed within boreholes or along cased portions of theinjection wells 130. U.S. Pat. No. 7,011,154 is entitled “In SituRecovery From a Kerogen and Liquid Hydrocarbon Containing Formation,”and describes such an arrangement. The '154 patent lists the use ofdownhole “insulated conductor heaters” such as cables, rods and pipes. Acurrent is passed through such conductive objects to generate resistiveheat. Alternatively, the heating may be accomplished by conductingelectricity through the formation to resistively heat a conductivebrine.

Any of the above-described heating methods may be used in connectionwith the hydrocarbon recovery methods disclosed herein. In addition,monitoring wells (not shown) may be placed between resistive heatingwells to determine when sufficient temperatures have been reachedbetween heating wells to adequately mobilize in situ hydrocarbons.

FIG. 5 is a flowchart showing steps for a method 500 of recovering aviscous hydrocarbon from a subsurface formation. The method may firstinclude creating an artificial barrier in a subterranean zone. This isshown in Box 510. The artificial barrier may be formed using any of themethods described above so as to create a topseal.

The subterranean zone is typically made up of sand or otherhigh-permeability matrix material. The subterranean zone is above orproximate a top of a subsurface formation. Preferably, the artificialbarrier is formed within 5 meters of the top of the subsurfaceformation. The artificial barrier is largely impermeable to fluid flow.

The method 500 also includes heating the subsurface formation. This isprovided in Box 520. The heating reduces the viscosity of the viscoushydrocarbon in the subsurface formation. Heating the subsurfaceformation also mobilizes the viscous hydrocarbon into a flowable heavyoil.

Heating may be conducted using any of the techniques described above.However, heating preferably involves injecting steam or a mixture ofsteam and a heated hydrocarbon solvent into the subsurface formation.Use of pure steam or vaporized heavier hydrocarbons (e.g., C₇+) may bebeneficial during the initial start-up of the gravity drainage processto speed the fluid connection of pairs of heat injection and fluidproduction wells. During later stages of development, a lighthydrocarbon solvent may be preferred.

The method 500 further includes producing the heavy oil to the surface.This is indicated at Box 530. The production process uses a productionmethod that maintains the integrity of the artificial barrier. Anexample is a gravity drainage method that provides for essentiallycontinuous production. Thermal transfer away from heat injection wellsreduces the viscosity of the bitumen sufficiently that it may gravitydrain to a production well at a commercially viable rate. The productionmethod is compatible with the artificial barrier as a low pressureprocess. This means that the production method does not compromise theintegrity of the topseal, such as by pressure-rupturing or chemicallydissolving the topseal.

Methods such as high pressure cyclic steam injection are not appropriatefor the present methods due to the risk of breaching the relatively thinartificial topseal with the injectant. Unlike in a deep reservoir, in ashallow reservoir the fracture pressure changes significantly from thebottom to top on a relative basis. There is a danger of a verticalfracture piercing to or through the artificial barrier, therebydefeating the utility of the topseal. Therefore, injection pressure iscontrolled so that the pressure at the top of a steam chamber staysbelow fracture pressure. The pressure at the top of a vapor-filledchamber will be similar to the pressure at the injection point due tothe small hydrostatic head of gas.

The viscous hydrocarbon may have a viscosity greater than about 1,000 cpin its undisturbed in situ state. In one aspect, the viscous hydrocarboncomprises primarily bitumen. After substantial heating, the viscoushydrocarbon will have a viscosity well below 100 cp.

FIG. 6 is a flowchart showing steps for a method 600 for recoveringviscous hydrocarbons from a subsurface formation, in an alternateembodiment.

The method 600 includes locating a permeable subterranean zonegeologically above the subsurface formation. This is shown at Box 610.In this instance, the subterranean zone is a permeable matrix such assand.

The method 600 also includes injecting a polymer solution into thesubterranean zone. This is provided at Box 620. The polymer solution isinjected in a liquid phase, but sets as a solid or gel. In one aspect,the polymer solution is a cross-linked polymer solution that slowlyreacts in situ to form a substantially solid material as the gel. Thepolymer solution spreads out over days or weeks within the subterraneanzone. The polymer solution may be formed using a heavy brine to aid inspreading the polymer solution along the bitumen or viscous hydrocarboninterface. As an alternative to a polymer solution, the injectant may bea temperature-sensitive gelling fluid that cools within the subterraneanzone 106 and hardens in situ.

The method 600 next includes allowing time for the polymer solution togel within the subterranean zone. This is provided at Box 630. As thepolymer solution gels, it forms an artificial topseal over thesubsurface formation.

The method 600 also includes forming a plurality of heat injection wellsinto the subsurface formation. This is provided at Box 640. The heatinjection wells are used to inject a heated vapor by any of the meansmentioned above. The heated vapor may be steam, heated hydrocarbonsolvent, or combinations thereof.

The method 600 further includes forming a plurality of producer wellsinto the subsurface formation. Each heat injection well has one or moreassociated producer wells, thereby creating sets of wells. This is seenat Box 650 of FIG. 6. In one aspect, each of the heat injection wells iscompleted horizontally within the subsurface formation. In anotheraspect, each of the producer wells is completed horizontally within thesubsurface formation. In one embodiment, each of the heat injectionwells is completed horizontally within the subsurface formation and eachof the producer wells is completed horizontally within the subsurfaceformation, such that each of the sets of wells is a pair of wells andeach of the pairs of wells is completed substantially within a verticalplane.

The method 600 also includes injecting steam into each of the pluralityof heat injection wells. This is presented in Box 660. The purpose is toheat the subsurface formation, thereby, (i) creating a steam chamberwithin the subsurface formation, (ii) reducing the viscosity of theviscous hydrocarbons, and (iii) mobilizing the viscous hydrocarbons intoa readily-flowable heavy oil. The steam may include one or morehydrocarbon components, such as from the C₃ to C₁₀ range.

The method 600 additionally includes producing the heavy oil througheach of the plurality of producer wells. This is presented in Box 670.In one aspect, the heavy oil flows gravitationally to the producer wellsthrough the steam chamber and along an oil drainage layer formednaturally around the steam chamber.

The method 600 further includes adjusting the composition of the steamby increasing the solvent content before the steam chamber reaches theartificial topseal. This optional step is shown at Box 680. This stepmay be performed by increasing the hydrocarbon solvent content of thesteam so that a light hydrocarbon solvent makes up at least 50% byvolume of the steam. Alternatively, the light hydrocarbon solvent makesup at least 75% by volume of the steam. The solvent is preferably in theC₃ to C₅ range. The steam with solvent may condense at or near theinterface with the artificial barrier.

As can be seen, methods are offered herein that provide improvedprocesses for extracting hydrocarbons from a shallow subsurfaceformation containing bitumen or tar. The improved processes utilize insitu recovery that are preferable to mining since the processes mayresult in less surface disruption, permit deeper targets, have lowerupfront capital expenses, and provide some in situ upgrading. In someembodiments, water usage is greatly reduced by using a hydrocarbonsolvent rather than steam to reduce in situ oil viscosity. The choice ofinjectant, injection pressures and operating temperatures arejudiciously chosen to be compatible with the artificial topseal.

While it will be apparent that the inventions herein described are wellcalculated to achieve the benefits and advantages set forth above, itwill be appreciated that the inventions are susceptible to modification,variation and change without departing from the spirit thereof Forexample, the methods disclosed herein allow for the formation of aneffective topseal over a hydrocarbon-bearing formation over an area thatis at least five acres, and preferably at least about ten acres.

1. A method of recovering a viscous hydrocarbon from a subsurfaceformation, comprising: creating an artificial barrier in a subterraneanzone above or proximate a top of the subsurface formation, the barrierbeing substantially continuous over an area that is at least about fiveacres (20,232 m²), and is largely impermeable to fluid flow; reducingthe viscosity of the viscous hydrocarbon in at least a portion of thesubsurface formation so as to mobilize the viscous hydrocarbon into aflowable heavy oil; and producing the heavy oil using a productionmethod that maintains the integrity of the artificial barrier.
 2. Themethod of claim 1, wherein reducing the viscosity of the viscoushydrocarbon comprises heating the subsurface formation.
 3. The method ofclaim 1, wherein reducing the viscosity of the viscous hydrocarboncomprises injecting a hydrocarbon solvent into the subsurface formation.4. The method of claim 3, wherein the hydrocarbon solvent comprisescomponents in the C₃ to C₁₀ range.
 5. The method of claim 1, wherein theviscous hydrocarbon has a viscosity greater than about 1,000 cp in itsundisturbed in situ state.
 6. The method of claim 5, wherein the viscoushydrocarbon comprises primarily bitumen.
 7. The method of claim 1,wherein the artificial barrier is formed above and within about fivemeters of the top of the subsurface formation.
 8. The method of claim 7,wherein: reducing the viscosity of the viscous hydrocarbon comprisesheating the subsurface formation; and heating the subsurface formationcomprises forming a plurality of heat-supplying wells.
 9. The method ofclaim 8, wherein: each of the heat-supplying wells carries an electriccurrent; and heating the subsurface formation comprises applyingelectrical-resistive heat to the subsurface formation to reduce theviscosity of the viscous hydrocarbon.
 10. The method of claim 8, whereineach of the heat-supplying wells injects a heated fluid.
 11. The methodof claim 10, wherein the injected fluid is injected at a pressure nogreater than about 300 psi above an initial reservoir pressure.
 12. Themethod of claim 10, wherein the injected fluid is injected at a pressureno greater than about 100 psi above an initial reservoir pressure. 13.The method of claim 10, where the heated fluid comprises a vaporizedfluid.
 14. The method of claim 13, wherein the vaporized fluid comprisessteam.
 15. The method of claim 14, wherein the vaporized fluid forms asteam chamber from which viscous hydrocarbons gravity-drain to aproduction well.
 16. The method of claim 15, wherein the vaporized fluidfurther comprises a hydrocarbon solvent.
 17. The method of claim 16,wherein the hydrocarbon solvent primarily comprises components in theC₃-C₅ range.
 18. The method of claim 16, wherein the hydrocarbon solventcondenses at initial in situ temperature conditions and in situpressures.
 19. The method of claim 8, wherein: producing the heavy oilprimarily utilizes gravity drainage; and production is continuous. 20.The method of claim 8, wherein: forming the plurality of heat injectionwells comprises forming first horizontal wells to serve as the heatinjection wells; the method further comprises forming second horizontalwells to serve as production wells; and wherein: the first and secondwells form respective pairs of wells; and the first and second wells arecompleted substantially within a vertical plane.
 21. The method of claim7, wherein creating an artificial barrier comprises injecting a gellingfluid into the subterranean zone, the gelling fluid forming a gel withinthe subterranean zone after a period of setting.
 22. The method of claim21, wherein: the gelling fluid is a polymer solution; and the polymersolution is injected into the subterranean zone at a pressure below afracture pressure of the subterranean zone.
 23. The method of claim 22,wherein: the polymer solution is a cross-linking polymer solution; andthe polymer solution forms the gel as a result of a chemical reaction insitu.
 24. The method of claim 21, wherein the gelling fluid hassufficient density to cause it to flow downward and spread over theviscous hydrocarbon proximate the top of the subsurface formation. 25.The method of claim 21, wherein: the gelling fluid is atemperature-sensitive emulsion containing wax which at least partiallysolidifies after injection as a result of cooling in situ; and theemulsion is injected into the subterranean zone.
 26. The method of claim7, further comprising: injecting a fluid into the subterranean zoneabove a fracture pressure so to form horizontal fractures and to formthe artificial barrier.
 27. The method of claim 26, wherein the injectedfluid is a polymer solution, a clay slurry, or cement.
 28. The method ofclaim 7, wherein creating an artificial barrier comprises injecting afluid into the subterranean zone, the fluid precipitating solidparticles within the subterranean zone and reducing formationpermeability.
 29. The method of claim 7, wherein creating an artificialbarrier comprises: completing a plurality of refrigerator wells in thesubterranean zone; circulating a cooling fluid through each of theplurality of refrigerator wells; and causing water in the subterraneanzone to substantially freeze in situ.
 30. The method of claim 29,wherein each refrigerator well comprises: an elongated tubular memberfor receiving the cooling fluid and for transporting the cooling fluidto the subterranean zone; and a first expansion valve in fluidcommunication with the tubular member through which the cooling fluidflows.
 31. The method of claim 29, further comprising: chilling thecooling fluid below ambient air temperature prior to circulating thecooling fluid through each of the plurality of refrigerator wells. 32.The method of claim 1, wherein the artificial barrier is substantiallycontinuous over at least 10 acres (40,464 m²).
 33. A method forrecovering viscous hydrocarbons from a subsurface formation, comprising:locating a permeable subterranean zone geologically above the subsurfaceformation; injecting a gelling fluid into the subterranean zone in aliquid phase; allowing time for the gelling fluid to gel within thesubterranean zone and form an artificial topseal over the subsurfaceformation; forming a plurality of heat injection wells into thesubsurface formation; forming a plurality of producer wells into thesubsurface formation such that each injector well has one or moreassociated producer wells, thereby creating sets of wells; injectingsteam into each of the plurality of heat injection wells in order toheat the subsurface formation, thereby, (i) creating steam chamberswithin the subsurface formation, (ii) reducing the viscosity of theviscous hydrocarbons, and (iii) mobilizing the viscous hydrocarbons intoa flowable heavy oil; and producing the heavy oil through each of theplurality of producer wells.
 34. The method of claim 33, wherein each ofthe heat injection wells is completed horizontally within the subsurfaceformation.
 35. The method of claim 33, wherein each of the producerwells is completed horizontally within the subsurface formation.
 36. Themethod of claim 34, wherein: each of the heat injection wells iscompleted horizontally within the subsurface formation; each of theproducer wells is completed horizontally within the subsurfaceformation, such that each of the sets of wells is a pair of wells; andeach of the pairs of wells is completed substantially within a verticalplane.
 37. The method of claim 33, further comprising: injecting ahydrocarbon solvent into the subsurface formation with the steam as thesteam chambers grow away from the heat injection wells.
 38. The methodof claim 37, wherein the hydrocarbon solvent comprises hydrocarboncomponents in the C₃ to C₅ range.
 39. The method of claim 33, wherein(i) the temperature of the injected steam is reduced before the steamchamber reaches the artificial topseal, (ii) the composition of theinjected steam is modified to include a hydrocarbon solvent afterinjection has begun, (iii) a pressure at which steam is injected throughthe heat injection wells is reduced after injection into the subsurfaceformation has begun, or (iv) combinations thereof, thereby preservingthe effectiveness of the artificial topseal.
 40. The method of claim 33,wherein the gelling fluid is a cross-linked polymer solution thatchemically reacts within the subterranean zone to form a gel.
 41. Themethod of claim 33, wherein: the gelling fluid is a waxy, oil-externalemulsion comprising oil, added wax, and water; the waxy emulsion isformulated to be substantially a solid at initial in situ temperatureconditions and in situ pressures in the subterranean zone; and themethod further comprises heating the waxy, oil-external emulsion into aflowable liquid at a surface heater before injecting the emulsion intothe permeable subterranean zone.
 42. The method of claim 41, wherein thewater concentration of the waxy emulsion is 40 to 60 volume % of water.